Seismic survey using an augmented reality device

ABSTRACT

Various implementations described herein are directed to a seismic survey using an augmented reality device. In one implementation, a method may include determining current location data of an augmented reality (AR) device in a physical environment. The method may also include receiving placement instructions for a first seismic survey equipment in the physical environment based on the current location data. The method may further include displaying the placement instructions in combination with a view of the physical environment on the AR device.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a continuation of U.S. patent application Ser. No.14/504,481, filed Oct. 2, 2014, which claims the benefit of U.S.Provisional Application No. 61/886,412, filed Oct. 3, 2013, the entirecontents of which are hereby incorporated by reference herein.

BACKGROUND

Seismic exploration may involve surveying subterranean geologicalformations for hydrocarbon deposits. A seismic survey may involvedeploying survey equipment, such as seismic source(s) and seismicsensors, at predetermined locations. The sources may generate seismicwaves, which propagate into the geological formations, creating pressurechanges and vibrations along their way. Changes in elastic properties ofthe geological formation may scatter the seismic waves, changing theirdirection of propagation and other properties. Part of the energyemitted by the sources may reach the seismic sensors. Some seismicsensors may be sensitive to pressure changes (hydrophones), others toparticle motion (e.g., geophones), and industrial surveys may deploy onetype of sensors or both. In response to the detected seismic events, thesensors may generate electrical signals to produce seismic data.Analysis of the seismic data can then indicate the presence or absenceof probable locations of hydrocarbon deposits.

In one scenario, deploying survey equipment in a production field may bea time-consuming process, depending on the conditions of the field,weather conditions, and/or the like. Similarly, the recovery and/orrepair of such equipment in the field may be slowed by the conditions ofthe field, lack of knowledge of the repairs needed, and/or the like.

SUMMARY

Described herein are implementations of various technologies andtechniques for a seismic survey using an augmented reality device. Inone implementation, a method may include determining current locationdata of an augmented reality (AR) device in a physical environment. Themethod may also include receiving placement instructions for a firstseismic survey equipment in the physical environment based on thecurrent location data. The method may further include displaying theplacement instructions in combination with a view of the physicalenvironment on the AR device.

In another implementation, a method may include determining currentlocation data of an augmented reality (AR) device in a physicalenvironment. The method may also include receiving data for plannedpositions for seismic survey equipment in the physical environment. Themethod may further include generating placement instructions for theseismic survey equipment based on the current location data and the datafor the planned positions. The method may additionally includedisplaying the placement instructions in combination with a view of thephysical environment on the AR device.

In yet another implementation, a method may include determining currentlocation data of an augmented reality (AR) device in a physicalenvironment, receiving position data for one or more seismic surveyequipment disposed in the physical environment, generating one or moreretrieval data for the one or more seismic survey equipment based on theposition data and the current location data, and displaying theretrieval data in combination with a view of the physical environment.

In still another implementation, a method may include displaying a viewof a physical environment on an augmented reality (AR) device, where thephysical environment includes seismic survey equipment disposed in theview. The method may also include receiving status data for the seismicsurvey equipment. The method may further include displaying the statusdata in combination with a view of the physical environment.

The above referenced summary section is provided to introduce aselection of concepts in a simplified form that are further describedbelow in the detailed description section. The summary is not intendedto be used to limit the scope of the claimed subject matter.Furthermore, the claimed subject matter is not limited toimplementations that solve any disadvantages noted in any part of thisdisclosure. Indeed, the systems, methods, processing procedures,techniques, and workflows disclosed herein may complement or replaceconventional methods for identifying, isolating, and/or processingvarious aspects of seismic signals or other data that is collected froma subsurface region or other multi-dimensional space, includingtime-lapse seismic data collected in a plurality of surveys.

BRIEF DESCRIPTION OF THE DRAWINGS

Implementations of various techniques will hereafter be described withreference to the accompanying drawings. It should be understood,however, that the accompanying drawings illustrate the variousimplementations described herein and are not meant to limit the scope ofvarious techniques described herein.

FIGS. 1.1-1.4 illustrate simplified, schematic views of an oilfieldhaving subterranean formation containing reservoir therein in accordancewith implementations of various technologies and techniques describedherein.

FIG. 2 illustrates a schematic view, partially in cross section of anoilfield having data acquisition tools positioned at various locationsalong the oilfield for collecting data of a subterranean formation inaccordance with implementations of various technologies and techniquesdescribed herein.

FIG. 3 illustrates an oilfield for performing production operations inaccordance with implementations of various technologies and techniquesdescribed herein.

FIG. 4 illustrates a seismic system in accordance with implementationsof various technologies and techniques described herein.

FIG. 5 illustrates a schematic diagram of a marine-based seismicacquisition system for use in a seismic survey in accordance withimplementations of various techniques described herein.

FIG. 6 illustrates a schematic diagram of a marine-based seismicacquisition system in accordance with implementations of varioustechniques described herein.

FIG. 7 illustrates an eyeglass device in accordance with implementationsof various techniques described herein.

FIG. 8 illustrates a flow diagram of a method for placing one or moreseismic sensors in a physical environment using an augmented reality(AR) device in accordance with implementations of various techniquesdescribed herein.

FIG. 9 illustrates a flow diagram of a method for retrieving one or moreseismic sensors in a physical environment using an AR device inaccordance with implementations of various techniques described herein.

FIG. 10 illustrates a schematic of a display of an AR device inaccordance with implementations of various techniques described herein.

FIG. 11 illustrates a flow diagram of a method for obtaining status datafor one or more seismic sensors in a physical environment using an ARdevice in accordance with implementations of various techniquesdescribed herein.

FIG. 12 illustrates a schematic of a display of an AR device inaccordance with implementations of various techniques described herein.

FIG. 13 illustrates a flow diagram of a method for placing a seismictruck in one or more planned positions in a physical environment usingan AR device in accordance with implementations of various techniquesdescribed herein.

FIG. 14 illustrates a flow diagram of a method for obtaining status datafor one or more seismic streamers in a physical environment using an ARdevice in accordance with implementations of various techniquesdescribed herein.

FIG. 15 illustrates a system diagram for determining a status of the oneor more seismic streamers disposed in a physical environment inaccordance with implementations of various techniques described herein.

FIG. 16 illustrates a schematic diagram of a display of an AR device inaccordance with implementations of various techniques described herein.

FIG. 17 illustrates a schematic diagram of a display of an AR device inaccordance with implementations of various techniques described herein.

FIG. 18 illustrates a system diagram for using an AR device with one ormore water vehicles disposed in a physical environment in accordancewith implementations of various techniques described herein.

FIG. 19 illustrates a schematic diagram of a computing system in whichthe various technologies described herein may be incorporated andpracticed.

DETAILED DESCRIPTION

The discussion below is directed to certain specific implementations. Itis to be understood that the discussion below is for the purpose ofenabling a person with ordinary skill in the art to make and use anysubject matter defined now or later by the patent “claims” found in anyissued patent herein.

It is specifically intended that the claims not be limited to theimplementations and illustrations contained herein, but include modifiedforms of those implementations including portions of the implementationsand combinations of elements of different implementations as come withinthe scope of the following claims.

Reference will now be made in detail to various implementations,examples of which are illustrated in the accompanying drawings andfigures. In the following detailed description, numerous specificdetails are set forth in order to provide a thorough understanding ofthe present disclosure. However, it will be apparent to one of ordinaryskill in the art that the present disclosure may be practiced withoutthese specific details. In other instances, well-known methods,procedures, components, circuits and networks have not been described indetail so as not to obscure aspects of the embodiments.

It will also be understood that, although the terms first, second, etc.may be used herein to describe various elements, these elements shouldnot be limited by these terms. These terms are used to distinguish oneelement from another. For example, a first object could be termed asecond object, and, similarly, a second object could be termed a firstobject, without departing from the scope of the claims. The first objectand the second object are both objects, respectively, but they are notto be considered the same object.

The terminology used in the description of the present disclosure hereinis for the purpose of describing particular implementations and is notintended to be limiting of the present disclosure. As used in thedescription of the present disclosure and the appended claims, thesingular forms “a,” “an” and “the” are intended to include the pluralforms as well, unless the context clearly indicates otherwise. It willalso be understood that the term “and/or” as used herein refers to andencompasses one or more possible combinations of one or more of theassociated listed items. It will be further understood that the terms“includes” and/or “including,” when used in this specification, specifythe presence of stated features, integers, operations, elements, and/orcomponents, but do not preclude the presence or addition of one or moreother features, integers, operations, elements, components and/or groupsthereof.

As used herein, the terms “up” and “down”; “upper” and “lower”;“upwardly” and downwardly”; “below” and “above”; and other similar termsindicating relative positions above or below a given point or elementmay be used in connection with some implementations of varioustechnologies described herein. However, when applied to equipment andmethods for use in wells that are deviated or horizontal, or whenapplied to equipment and methods that when arranged in a well are in adeviated or horizontal orientation, such terms may refer to a left toright, right to left, or other relationships as appropriate.

It should also be noted that in the development of any such actualimplementation, numerous decisions specific to circumstance may be madeto achieve the developer's specific goals, such as compliance withsystem-related and business-related constraints, which will vary fromone implementation to another. Moreover, it will be appreciated thatsuch a development effort might be complex and time-consuming but wouldnevertheless be a routine undertaking for those of ordinary skill in theart having the benefit of this disclosure.

The terminology and phraseology used herein is solely used fordescriptive purposes and should not be construed as limiting in scope.Language such as “having,” “containing,” or “involving,” and variationsthereof, is intended to be broad and encompass the subject matter listedthereafter, equivalents, and additional subject matter not recited.

Furthermore, the description and examples are presented solely for thepurpose of illustrating the different embodiments, and should not beconstrued as a limitation to the scope and applicability. While anycomposition or structure may be described herein as having certainmaterials, it should be understood that the composition could optionallyinclude two or more different materials. In addition, the composition orstructure may also include some components other than the ones alreadycited. It should also be understood that throughout this specification,when a range is described as being useful, or suitable, or the like, itis intended that any value within the range, including the end points,is to be considered as having been stated. Furthermore, respectivenumerical values should be read once as modified by the term “about”(unless already expressly so modified) and then read again as not to beso modified unless otherwise stated in context. For example, “a range offrom 1 to 10” is to be read as indicating a respective possible numberalong the continuum between about 1 and about 10. In other words, when acertain range is expressed, even if a few specific data points areexplicitly identified or referred to within the range, or even when nodata points are referred to within the range, it is to be understoodthat the inventors appreciate and understand that any data points withinthe range are to be considered to have been specified, and that theinventors have possession of the entire range and points within therange.

As used herein, the term “if” may be construed to mean “when” or “upon”or “in response to determining” or “in response to detecting,” dependingon the context. Similarly, the phrase “if it is determined” or “if [astated condition or event] is detected” may be construed to mean “upondetermining” or “in response to determining” or “upon detecting [thestated condition or event]” or “in response to detecting [the statedcondition or event],” depending on the context.

One or more implementations of various techniques for a seismic surveyusing an augmented reality device will now be described in more detailwith reference to FIGS. 1-18 in the following paragraphs.

Production Environment & Seismic Acquisition

Seismic exploration may involve surveying subterranean geologicalformations for hydrocarbon deposits. A seismic survey may involvedeploying seismic equipment, such as seismic source(s) and seismicsensors, at predetermined locations in one or more variousconfigurations, as further explained below.

FIGS. 1.1-1.4 illustrate simplified, schematic views of a productionfield 100 having a subterranean formation 102 containing reservoir 104therein in accordance with implementations of various technologies andtechniques described herein. The production field 100 may be anoilfield, a gas field, and/or the like. FIG. 1.1 illustrates a surveyoperation being performed by a survey tool, such as seismic truck 106.1,to measure properties of the subterranean formation 102. The surveyoperation may be a seismic survey operation for producing soundvibrations. In FIG. 1.1, one such sound vibration, e.g., sound vibration112 generated by source 110, may reflect off horizons 114 in earthformation 116. A set of sound vibrations may be received by sensors,such as geophone-receivers 118, situated on the earth's surface. Thedata received 120 may be provided as input data to a computer 122.1 of aseismic truck 106.1, and responsive to the input data, computer 122.1generates seismic data output 124. This seismic data output may bestored, transmitted or further processed as desired, for example, bydata reduction.

FIG. 1.2 illustrates a drilling operation being performed by drillingtools 106.2 suspended by rig 128 and advanced into subterraneanformations 102 to form wellbore 136. Mud pit 130 may be used to drawdrilling mud into the drilling tools via flow line 132 for circulatingdrilling mud down through the drilling tools, then up wellbore 136 andback to the surface. The drilling mud may be filtered and returned tothe mud pit. A circulating system may be used for storing, controlling,or filtering the flowing drilling mud. The drilling tools may beadvanced into subterranean formations 102 to reach reservoir 104. Eachwell may target one or more reservoirs. The drilling tools may beadapted for measuring downhole properties using logging while drillingtools. The logging while drilling tools may also be adapted for takingcore sample 133 as shown.

Computer facilities may be positioned at various locations about theproduction field 100 (e.g., the surface unit 134) and/or at remotelocations. Surface unit 134 may be used to communicate with the drillingtools and/or offsite operations, as well as with other surface ordownhole sensors. Surface unit 134 may be capable of communicating withthe drilling tools to send commands to the drilling tools, and toreceive data therefrom. Surface unit 134 may also collect data generatedduring the drilling operation and produce data output 135, which maythen be stored or transmitted.

Sensors (S), such as gauges, may be positioned about production field100 to collect data relating to various production field operations asdescribed previously. As shown, sensor (S) may be positioned in one ormore locations in the drilling tools and/or at rig 128 to measuredrilling parameters, such as weight on bit, torque on bit, pressures,temperatures, flow rates, compositions, rotary speed, and/or otherparameters of the field operation. Sensors (S) may also be positioned inone or more locations in the circulating system.

Drilling tools 106.2 may include a bottom hole assembly (BHA) (notshown), generally referenced, near the drill bit (e.g., within severaldrill collar lengths from the drill bit). The bottom hole assembly mayinclude capabilities for measuring, processing, and storing information,as well as communicating with surface unit 134. The bottom hole assemblymay further include drill collars for performing various othermeasurement functions.

The bottom hole assembly may include a communication subassembly thatcommunicates with surface unit 134. The communication subassembly may beadapted to send signals to and receive signals from the surface using acommunications channel such as mud pulse telemetry, electro-magnetictelemetry, or wired drill pipe communications. The communicationsubassembly may include, for example, a transmitter that generates asignal, such as an acoustic or electromagnetic signal, which isrepresentative of the measured drilling parameters. It may beappreciated by one of skill in the art that a variety of telemetrysystems may be employed, such as wired drill pipe, electromagnetic orother known telemetry systems.

The wellbore may be drilled according to a drilling plan that isestablished prior to drilling. The drilling plan may set forthequipment, pressures, trajectories and/or other parameters that definethe drilling process for the wellsite. The drilling operation may thenbe performed according to the drilling plan. However, as information isgathered, the drilling operation may need to deviate from the drillingplan. Additionally, as drilling or other operations are performed, thesubsurface conditions may change. The earth model may also needadjustment as new information is collected.

The data gathered by sensors (S) may be collected by surface unit 134and/or other data collection sources for analysis or other processing.The data collected by sensors (S) may be used alone or in combinationwith other data. The data may be collected in one or more databasesand/or transmitted on or offsite. The data may be historical data, realtime data, or combinations thereof. The real time data may be used inreal time, or stored for later use. The data may also be combined withhistorical data or other inputs for further analysis. The data may bestored in separate databases, or combined into a single database.

Surface unit 134 may include transceiver 137 to allow communicationsbetween surface unit 134 and various portions of the production field100 or other locations. Surface unit 134 may also be provided with orfunctionally connected to one or more controllers (not shown) foractuating mechanisms at production field 100. Surface unit 134 may thensend command signals to production field 100 in response to datareceived. Surface unit 134 may receive commands via transceiver 137 ormay itself execute commands to the controller. A processor may beprovided to analyze the data (locally or remotely), make the decisionsand/or actuate the controller. In this manner, production field 100 maybe selectively adjusted based on the data collected. This technique maybe used to optimize portions of the field operation, such as controllingdrilling, weight on bit, pump rates, or other parameters. Theseadjustments may be made automatically based on computer protocol, and/ormanually by an operator. In some cases, well plans may be adjusted toselect optimum operating conditions, or to avoid problems.

FIG. 1.3 illustrates a wireline operation being performed by wirelinetool 106.3 suspended by rig 128 and into wellbore 136 of FIG. 1.2.Wireline tool 106.3 may be adapted for deployment into wellbore 136 forgenerating well logs, performing downhole tests and/or collectingsamples. Wireline tool 106.3 may be used to provide another method andapparatus for performing a seismic survey operation. Wireline tool 106.3may, for example, have an explosive, radioactive, electrical, oracoustic energy source 144 that sends and/or receives electrical signalsto surrounding subterranean formations 102 and fluids therein.

Wireline tool 106.3 may be operatively connected to, for example,geophones 118 and a computer 122.1 of a seismic truck 106.1 of FIG. 1.1.Wireline tool 106.3 may also provide data to surface unit 134. Surfaceunit 134 may collect data generated during the wireline operation andmay produce data output 135 that may be stored or transmitted. Wirelinetool 106.3 may be positioned at various depths in the wellbore 136 toprovide a survey or other information relating to the subterraneanformation 102.

Sensors (S), such as gauges, may be positioned about production field100 to collect data relating to various field operations as describedpreviously. As shown, sensor S may be positioned in wireline tool 106.3to measure downhole parameters which relate to, for example porosity,permeability, fluid composition and/or other parameters of the fieldoperation.

FIG. 1.4 illustrates a production operation being performed byproduction tool 106.4 deployed from a production unit or Christmas tree129 and into completed wellbore 136 for drawing fluid from the downholereservoirs into surface facilities 142. The fluid flows from reservoir104 through perforations in the casing (not shown) and into productiontool 106.4 in wellbore 136 and to surface facilities 142 via gatheringnetwork 146.

Sensors (S), such as gauges, may be positioned about production field100 to collect data relating to various field operations as describedpreviously. As shown, the sensor (S) may be positioned in productiontool 106.4 or associated equipment, such as Christmas tree 129,gathering network 146, surface facility 142, and/or the productionfacility, to measure fluid parameters, such as fluid composition, flowrates, pressures, temperatures, and/or other parameters of theproduction operation.

Production may also include injection wells for added recovery. One ormore gathering facilities may be operatively connected to one or more ofthe wellsites for selectively collecting downhole fluids from thewellsite(s).

While FIGS. 1.2-1.4 illustrate tools used to measure properties of aproduction field, such as an oilfield or gas field, it may beappreciated that the tools may be used in connection with otheroperations, such as mines, aquifers, storage, or other subterraneanfacilities. Also, while certain data acquisition tools are depicted, itmay be appreciated that various measurement tools capable of sensingparameters, such as seismic two-way travel time, density, resistivity,production rate, etc., of the subterranean formation and/or itsgeological formations may be used. Various sensors (S) may be located atvarious positions along the wellbore and/or the monitoring tools tocollect and/or monitor the desired data. Other sources of data may alsobe provided from offsite locations.

The field configurations of FIGS. 1.1-1.4 may be an example of a fieldusable with oilfield or gas field application frameworks. At least partof the production field 100 may be on land, water, and/or sea. Also,while a single field measured at a single location may be depicted,oilfield or gas field applications may be utilized with any combinationof one or more oilfields and/or gas field, one or more processingfacilities and one or more wellsites.

FIG. 2 illustrates a schematic view, partially in cross section ofproduction field 200 having data acquisition tools 202.1, 202.2, 202.3and 202.4 positioned at various locations along production field 200 forcollecting data of subterranean formation 204 in accordance withimplementations of various technologies and techniques described herein.The production field 200 may be an oilfield, a gas field, and/or thelike. Data acquisition tools 202.1-202.4 may be the same as dataacquisition tools 106.1-106.4 of FIGS. 1.1-1.4, respectively, or othersnot depicted. As shown, data acquisition tools 202.1-202.4 may generatedata plots or measurements 208.1-208.4, respectively. These data plotsmay be depicted along production field 200 to demonstrate the datagenerated by the various operations.

Data plots 208.1-208.3 may be examples of static data plots that may begenerated by data acquisition tools 202.1-202.3, respectively; however,it should be understood that data plots 208.1-208.3 may also be dataplots that are updated in real time. These measurements may be analyzedto better define the properties of the formation(s) and/or determine theaccuracy of the measurements and/or for checking for errors. The plotsof each of the respective measurements may be aligned and scaled forcomparison and verification of the properties.

Static data plot 208.1 may be a seismic two-way response over a periodof time. Static plot 208.2 may be core sample data measured from a coresample of the formation 204. The core sample may be used to providedata, such as a graph of the density, porosity, permeability, or someother physical property of the core sample over the length of the core.Tests for density and viscosity may be performed on the fluids in thecore at varying pressures and temperatures. Static data plot 208.3 maybe a logging trace that may provide a resistivity or other measurementof the formation at various depths.

A production decline curve or graph 208.4 may be a dynamic data plot ofthe fluid flow rate over time. The production decline curve may providethe production rate as a function of time. As the fluid flows throughthe wellbore, measurements may be taken of fluid properties, such asflow rates, pressures, composition, etc.

Other data may also be collected, such as historical data, user inputs,economic information, and/or other measurement data and other parametersof interest. As described below, the static and dynamic measurements maybe analyzed and used to generate models of the subterranean formation todetermine characteristics thereof. Similar measurements may also be usedto measure changes in formation aspects over time.

The subterranean structure 204 may have a plurality of geologicalformations 206.1-206.4. As shown, this structure may have severalformations or layers, including a shale layer 206.1, a carbonate layer206.2, a shale layer 206.3 and a sand layer 206.4. A fault 207 mayextend through the shale layer 206.1 and the carbonate layer 206.2. Thestatic data acquisition tools may be adapted to take measurements anddetect characteristics of the formations.

While a specific subterranean formation with specific geologicalstructures is depicted, it may be appreciated that production field 200may contain a variety of geological structures and/or formations,sometimes having extreme complexity. In some locations, such as belowthe water line, fluid may occupy pore spaces of the formations. Each ofthe measurement devices may be used to measure properties of theformations and/or its geological features. While each acquisition toolmay be shown as being in specific locations in production field 200, itmay be appreciated that one or more types of measurement may be taken atone or more locations across one or more fields or other locations forcomparison and/or analysis.

The data collected from various sources, such as the data acquisitiontools of FIG. 2, may then be processed and/or evaluated. The seismicdata displayed in static data plot 208.1 from data acquisition tool202.1 may be used by a geophysicist to determine characteristics of thesubterranean formations and features. The core data shown in static plot208.2 and/or log data from well log 208.3 may be used by a geologist todetermine various characteristics of the subterranean formation. Theproduction data from graph 208.4 may be used by the reservoir engineerto determine fluid flow reservoir characteristics. The data analyzed bythe geologist, geophysicist and the reservoir engineer may be analyzedusing modeling techniques.

FIG. 3 illustrates a production field 300 for performing productionoperations in accordance with implementations of various technologiesand techniques described herein. The production field 300 may be anoilfield, a gas field, and/or the like. As shown, the production field300 may have a plurality of wellsites 302 operatively connected tocentral processing facility 354. The production field configuration ofFIG. 3 may not be intended to limit the scope of the production fieldapplication system. At least part of the production field may be on landand/or sea. Also, while a single production field with a singleprocessing facility and a plurality of wellsites is depicted, anycombination of one or more production fields, one or more processingfacilities and one or more wellsites may be present.

Each wellsite 302 may have equipment that forms wellbore 336 into theearth. The wellbores may extend through subterranean formations 306including reservoirs 304. These reservoirs 304 may contain fluids, suchas hydrocarbons. The wellsites may draw fluid from the reservoirs andpass them to the processing facilities via surface networks 344. Thesurface networks 344 may have tubing and control mechanisms forcontrolling the flow of fluids from the wellsite to processing facility354.

FIG. 4 illustrates a seismic system 20 in accordance withimplementations of various technologies and techniques described herein.The seismic system 20 may include a plurality of tow vessels 22 that areemployed to enable seismic profiling, e.g. three-dimensional verticalseismic profiling or rig/offset vertical seismic profiling. In FIG. 4, amarine system may include a rig 50, a plurality of vessels 22, and oneor more acoustic receivers 28. Although a marine system is illustrated,other implementations of the disclosure may not be limited to thisexample. A person of ordinary skill in the art may recognize that landor offshore systems may be used.

Although two vessels 22 are illustrated in FIG. 4, a single vessel 22with multiple source arrays 24 or multiple vessels 22 with single ormultiple sources 24 may be used. In some implementations, at least onesource and/or source array 24 may be located on the rig 50, as shown bythe rig source in FIG. 4. As the vessels 22 travel on predetermined orsystematic paths, their locations may be recorded through the use ofnavigation system 36. In some implementations, the navigation system 36may utilize a global positioning system (GPS) 38 to record the position,speed, direction, and other parameters of the tow vessels 22.

As shown, the global positioning system 38 may utilize or work incooperation with satellites 52 which operate on a suitable communicationprotocol, e.g. VSAT communications. The VSAT communications may be used,among other things, to supplement VHF and UHF communications. The GPSinformation can be independent of the VSAT communications and may beinput to a processing system or other suitable processors to predict thefuture movement and position of the vessels 22 based on real-timeinformation. In addition to predicting future movements, the processingsystem also can be utilized to provide directions and coordinates aswell as to determine initial shot times, as described above. A controlsystem effectively utilizes the processing system in cooperation with asource controller and a synchronization unit to synchronize the sources24 with the downhole data acquisition system 26.

As shown, the one or more vessels 22 may respectively tow one or moreacoustic sources/source arrays 24. The source arrays 24 include one ormore seismic signal generators 54, e.g. air guns, configured to create aseismic and/or sonic disturbance. In the implementation illustrated, thetow vessels 22 comprise a master source vessel 56 (Vessel A) and a slavesource vessel 57 (Vessel B). However, other numbers and arrangements oftow vessels 22 may be employed to accommodate the parameters of a givenseismic profiling application. For example, one source 24 may be mountedat rig 50 (see FIG. 4) or at another suitable location, and both vessels22 may serve as slave vessels with respect to the rig source 24 or withrespect to a source at another location.

However, a variety of source arrangements and implementations may beused. When utilizing dithered timing between the sources, for example,the master and slave locations of the sources can be adjusted accordingto the parameters of the specific seismic profiling application. In someimplementations, one of the source vessels 22 (e.g. source vessel A inFIG. 4) may serve as the master source vessel while the other sourcevessel 22 serves as the slave source vessel with dithered firing.However, an alternate source vessel 22 (e.g. source vessel B in FIG. 4)may serve as the master source vessel while the other source vessel 22serves as the slave source vessel with dithered firing.

Similarly, the rig source 22 may serve as the master source while one ofthe source vessels 22 (e.g. vessel A) serves as the slave source vesselwith dithered firing. The rig source 22 also may serve as the mastersource while the other source vessel 22 (e.g. vessel B) serves as theslave source vessel with dithered firing. In some implementations, therig source 22 may serve as the master source while both of the sourcevessels 22 serve as slave source vessels each with dithered firings.These and other implementations may be used in achieving the desiredsynchronization of sources 22 with the downhole acquisition system 26.

The acoustic receivers 28 of data acquisition system 26 may be deployedin borehole 30 via a variety of delivery systems, such as wirelinedelivery systems, slickline delivery systems, and other suitabledelivery systems. Although a single acoustic receiver 28 could be usedin the borehole 30, a plurality of receivers 28, as shown, may belocated in a variety of positions and orientations. The acousticreceivers 28 may be configured for sonic and/or seismic reception.Additionally, the acoustic receivers 28 may be communicatively coupledwith processing equipment 58 located downhole. In one implementation,processing equipment 58 may comprise a telemetry system for transmittingdata from acoustic receivers 28 to additional processing equipment 59located at the surface, e.g. on the rig 50 and/or vessels 22.

Depending on the data communication system, surface processing equipment59 may include a radio repeater 60, an acquisition and logging unit 62,and a variety of other and/or additional signal transfer components andsignal processing components. The radio repeater 60 along with othercomponents of processing equipment 59 may be used to communicatesignals, e.g. UHF and/or VHF signals, between vessels 22 and rig 50 andto enable further communication with downhole data acquisition system26.

It should be noted the UHF and VHF signals can be used to supplementeach other. The UHF band may support a higher data rate throughput, butcan be susceptible to obstructions and has less range. The VHF band maybe less susceptible to obstructions and may have increased radio rangebut its data rate throughput is lower. In FIG. 4, the VHF communicationsmay “punch through” an obstruction in the form of a production platform.

In some implementations, the acoustic receivers 28 may be coupled tosurface processing equipment 59 via a hardwired connection. In otherimplementations, wireless or optical connections may be employed. Instill other implementations, combinations of coupling techniques may beemployed to relay information received downhole via the acousticreceivers 28 to an operator and/or the control system described above,located at least in part at the surface.

In addition to providing raw or processed data uphole to the surface,the coupling system, e.g. downhole processing equipment 58 and surfaceprocessing equipment 59, may be designed to transmit data orinstructions downhole to the acoustic receivers 28. For example, thesurface processing equipment 59 may comprise a synchronization unit,which may coordinate the firing of sources 24, e.g. dithered (delayed)source arrays, with the acoustic receivers 28 located in borehole 30. Inone implementation, the synchronization unit may use a coordinateduniversal time to ensure accurate timing. In some implementations, thecoordinated universal time system may be employed in cooperation withglobal positioning system 38 to obtain UTC data from the GPS receiversof GPS system 38.

FIG. 4 illustrates one example of a system for performing seismicprofiling that can employ simultaneous or near-simultaneous acquisitionof seismic data. In one implementation, the seismic profiling maycomprise three-dimensional vertical seismic profiling, but otherapplications may utilize rig and/or offset vertical seismic profiling orseismic profiling employing walkaway lines. An offset source can beprovided by a source 24 located on rig 50, on a vessel 22, and/or onanother vessel or structure. In one implementation, the vessels 22 maybe substantially stationary.

In one implementation, the overall seismic system 20 may employ variousarrangements of sources 24 on vessels 22 and/or rig 50 with eachlocation having at least one source and/or source array 24 to generateacoustic source signals. The acoustic receivers 28 of downholeacquisition system 26 may be configured to receive the source signals,at least some of which are reflected off a reflection boundary 64located beneath a sea bottom 66. The acoustic receivers 28 may generatedata streams that are relayed uphole to a suitable processing system,e.g. the processing system described above, via downholetelemetry/processing equipment 58.

While the acoustic receivers 28 generate data streams, the navigationsystem 36 may determine a real-time speed, position, and direction ofeach vessel 22 and may estimate initial shot times accomplished viasignal generators 54 of the appropriate source arrays 24. The sourcecontroller may be part of surface processing equipment 59 (located onrig 50, on vessels 22, or at other suitable locations) and may bedesigned to control firing of the acoustic source signals so that thetiming of an additional shot time (e.g. a shot time via slave vessel 57)is based on the initial shot time (e.g. a shot time via master vessel56) plus a dither value.

The synchronization unit of, for example, surface processing equipment59, may coordinate the firing of dithered acoustic signals withrecording of acoustic signals by the downhole acquisition system 26. Theprocessor system may be configured to separate a data stream of theinitial shot and a data stream of the additional shot via a coherencyfilter. As discussed above, however, other implementations may employpure simultaneous acquisition and/or may not use separation of the datastreams. In such implementations, the dither is effectively zero.

After an initial shot time at T=0 (T0) is determined, subsequent firingsof acoustic source arrays 24 may be offset by a dither. The dithers canbe positive or negative and sometimes are created as pre-defined randomdelays. Use of dithers facilitates the separation of simultaneous ornear-simultaneous data sets to simplify the data processing. The abilityto have the acoustic source arrays 24 fire in simultaneous ornear-simultaneous patterns may reduce the overall amount of time forthree-dimensional vertical seismic profiling source acquisition. This,in turn, may significantly reduce rig time. As a result, the overallcost of the seismic operation may be reduced, rendering the dataintensive process much more accessible.

If the acoustic source arrays used in the seismic data acquisition arewidely separated, the difference in move-outs across the acousticreceiver array of the wave fields generated by the acoustic sources 24can be used to obtain a clean data image via processing the data withoutfurther special considerations. However, even when the acoustic sources24 are substantially co-located in time, data acquired by any of themethods involving dithering of the firing times of the individualsources 24 described herein can be processed to a formation imageleaving hardly any artifacts in the final image. This is accomplished bytaking advantage of the incoherence of the data generated by oneacoustic source 24 when seen in the reference time of the other acousticsource 24.

Attention is now directed to methods, techniques, and workflows forprocessing and/or transforming collected data that are in accordancewith some implementations. Some operations in the processing procedures,methods, techniques, and workflows disclosed herein may be combinedand/or the order of some operations may be changed. In the geosciencesand/or other multi-dimensional data processing disciplines, variousinterpretations, sets of assumptions, and/or domain models such asvelocity models, may be refined in an iterative fashion; this conceptmay be applicable to the procedures, methods, techniques, and workflowsas discussed herein. This iterative refinement can include use offeedback loops executed on an algorithmic basis, such as via a computingsystem, as discussed later, and/or through manual control by a user whomay make determinations regarding whether a given action, template, ormodel has become accurate.

FIG. 5 illustrates a schematic diagram of a marine-based seismicacquisition system 501 for use in a seismic survey in accordance withimplementations of various techniques described herein. In system 501,survey vessel 500 tows one or more seismic streamers 505 (one streamer505 being depicted in FIG. 5) behind the vessel 500. In oneimplementation, streamers 505 may be arranged in a spread 504 in whichmultiple streamers 505 are towed in approximately the same plane at thesame depth. Although various techniques are described herein withreference to a marine-based seismic acquisition system shown in FIG. 5,it should be understood that other marine-based seismic acquisitionsystem configurations may also be used. For instance, the streamers 505may be towed at multiple planes and/or multiple depths, such as in anover/under configuration. In one implementation, the streamers 505 maybe towed in a slanted configuration, where fronts of the streamers aretowed shallower than tail ends of the streamers.

Seismic streamers 505 may be several thousand meters long and maycontain various support cables, as well as wiring and/or circuitry thatmay be used to facilitate communication along the streamers 505. Ingeneral, each streamer 505 may include a primary cable where seismicreceivers that record seismic signals may be mounted. In oneimplementation, seismic receivers may include hydrophones that acquirepressure data. In another implementation, seismic receivers may includemulti-component sensors such that each sensor is capable of detecting apressure wavefield and at least one component of a particle motion thatis associated with acoustic signals that are proximate to the sensor.Examples of particle motions include one or more components of aparticle displacement, one or more components (i.e., inline (x),crossline (y) and vertical (z) components) of a particle velocity andone or more components of a particle acceleration.

Depending on the particular survey need, the multi-component seismicreceiver may include one or more hydrophones, geophones, particledisplacement sensors, particle velocity sensors, accelerometers,pressure gradient sensors, or combinations thereof. In oneimplementation, the multi-component seismic receiver may be implementedas a single device or may be implemented as a plurality of devices.

Marine-based seismic data acquisition system 501 may also include one ormore seismic sources, such as air guns and the like. In oneimplementation, seismic sources may be coupled to, or towed by, thesurvey vessel 500. In another implementation, seismic sources mayoperate independently of the survey vessel 500 in that the sources maybe coupled to other vessels or buoys.

As seismic streamers 505 are towed behind the survey vessel 500,acoustic signals, often referred to as “shots,” may be produced by theseismic sources and are directed down through a water column 506 intostrata 510 beneath a water bottom surface 508. Acoustic signals may bereflected from the various subterranean geological formations, such asformation 514 depicted in FIG. 5. The incident acoustic signals that aregenerated by the sources may produce corresponding reflected acousticsignals, or pressure waves, which may be sensed by seismic sensors ofthe seismic streamers 505.

The seismic sensors may generate signals, called “traces,” whichindicate the acquired measurements of the pressure wavefield andparticle motion. The traces (i.e., seismic data) may be recorded and maybe processed by a signal processing unit or a controller 520 deployed onthe survey vessel 500.

The goal of the seismic acquisition may be to build up an image of asurvey area for purposes of identifying subterranean geologicalformations, such as the geological formation 514. Subsequent analysis ofthe image may reveal probable locations of hydrocarbon deposits insubterranean geological formations. In one implementation, portions ofthe analysis of the image may be performed on the seismic survey vessel500, such as by the controller 520.

A particular seismic source may be part of an array of seismic sourceelements (such as air guns, for example) that may be arranged in strings(gun strings, for example) of the array. Regardless of the particularcomposition of the seismic sources, the sources may be fired in aparticular time sequence during the survey. Although FIG. 5 illustratesa marine-based seismic acquisition system, the marine-based seismicacquisition system is merely provided as an example of a seismicacquisition system that may be used with the methods described herein.It should be noted that the methods described herein may also beperformed on a seabed-based seismic acquisition system, or a transitionzone-based seismic acquisition system.

In addition to the seismic sources and receivers, an acousticpositioning system may be used to determine the positions of seismicacquisition equipment used in the seismic acquisition system 501, suchas the seismic streamers 505 and the seismic receivers disposed thereon.The acoustic positioning system may include one or more acousticpositioning sources 516 and one or more acoustic positioning receivers518. In one implementation, the acoustic positioning sources 516 and theacoustic positioning receivers 518 may be disposed along the one or moreseismic streamers 505. In such an implementation, and as describedfurther below, power and/or control electronics may be incorporated intothe one or more seismic streamers 505 as well. In a furtherimplementation, the acoustic positioning system may be a stand-alonesystem with separate power supply and communication telemetry links tothe survey vessel 500.

In one implementation, the acoustic positioning receivers 518 may be thesame as the seismic receivers described above or some subset of theseismic receivers. The acoustic positioning sources 516 may be higherfrequency acoustic sources, as opposed to the seismic sources describedabove that may be used for performing a seismic survey operation and maybe of a lower frequency. The acoustic positioning sources 516 mayinclude an acoustic transmitter or any other implementation known tothose skilled in the art. In some implementations, the acousticpositioning source 516 and the acoustic positioning receiver may becombined into a single physical unit. In some implementations, anacoustic positioning source 516 and an acoustic positioning receiver 518may be combined into one transducer unit. In such an implementation, thetransducer unit may act as an acoustic positioning source 516, anacoustic positioning acoustic positioning receiver 518, or both.

The controller 520 may be configured to control activation of theacoustic positioning sources 516 of the acoustic positioning system. Inparticular, and as further discussed below with respect to the operationof the acoustic positioning system, the acoustic positioning sources 516may produce one or more acoustic positioning signals that may berecorded by the acoustic positioning receivers 518. In oneimplementation, an acoustic positioning receiver 518 may detect acousticpositioning signals from an acoustic positioning source 516 locatedwithin the same seismic streamer 505 as the acoustic positioningreceiver 518. In another implementation, an acoustic positioningreceiver 518 may detect acoustic positioning signals from an acousticpositioning source 516 located within a different seismic streamer 505as the acoustic positioning receiver 518.

As also discussed below with respect to the operation of the acousticpositioning system, the controller 520 may be configured to process theacoustic positioning signals collected by the acoustic positioningreceivers 518. In particular, processing an acquired acousticpositioning signal may yield the travel time of the signal between anacoustic positioning source 516 and an acoustic positioning receiver518. In turn, the travel time may be used to derive the travel distanceof the acoustic positioning signal between the acoustic positioningsource 516 and the acoustic positioning receiver 518. This traveldistance can then be used to calculate the relative positions of theacoustic positioning source 516 and/or the acoustic positioning receiver518 in the seismic streamer 505. A distance between relative positionsof an acoustic positioning source 516 and an acoustic positioningreceiver 518 may be referred to as a range.

In one implementation, the controller 520 may process the relativepositions and other information to produce (or update) a positioningmodel to enable estimation of positioning of the seismic acquisitionequipment (e.g., position of a seismic streamer 505, depth of a seismicstreamer 505, distances between seismic receivers, etc.).

FIG. 6 illustrates a schematic diagram of a marine-based seismicacquisition system 600 in accordance with implementations of varioustechniques described herein. The system 600 may include one or morewater vehicles 610, which may be adapted to descend through a watercolumn or may be adapted for movement on a sea surface via a thrust orpropulsion mechanism. In one implementation, the water vehicle 610 maybe unmanned. For example, the unmanned water vehicle 610 may take theform of an autonomously operating vehicle (AOV) or a remotely operatingvehicle (ROV) maneuvering on the sea surface, such as a wave glider or ahybrid water vehicle. The wave glider may be configured to harness waveenergy to impart motion to the wave glider, such as the wave gliderdescribed in U.S. Pat. No. 7,371,136 entitled WAVE POWER, which isincorporated herein by reference. The hybrid water vehicle may beconfigured to combine mechanical propulsion methods with energyharvesting principles, such as the energy harvesting principles used bywave gliders. In other implementations, the water vehicle 610 may takethe form of a diving wave glider, a submarine water vehicle, a sailbuoy, or any other implementation known to those skilled in the art.

The water vehicle 610 may be used for seismic surveying and may includeone or more sensors 612. The sensors 612 may be disposed on one or morestreamers 614 coupled to the water vehicle 610, where the streamer 614may descend in a generally vertical direction from the water vehicle 610into the water column. In one implementation, the streamer 614 maydescend 615 meters below the sea surface.

The seismic sensors 612 may be pressure sensors, particle motionsensors, or multi-component seismic sensors. For the case ofmulti-component seismic sensors, the seismic sensors 612 are capable ofdetecting a pressure wavefield and at least one component of a particlemotion that is associated with acoustic signals that are proximate tothe multi-component seismic sensor. Examples of particle motions includeone or more components of a particle displacement, one or morecomponents (inline (x), crossline (y) and vertical (z) components) of aparticle velocity and one or more components of a particle acceleration.

Multi-component seismic sensors may include one or more geophones,hydrophones, particle displacement sensors, optical sensors, particlevelocity sensors, accelerometers, pressure gradient sensors, orcombinations thereof. For example, a particular multi-component seismicsensor may include three orthogonally-aligned accelerometers (e.g., athree-component micro electro-mechanical system (MEMS) accelerometer) tomeasure three corresponding orthogonal components of particle velocityand/or acceleration near the seismic sensor. In such implementations,the MEMS-based sensor may be a capacitive MEMS-based sensor of the typedescribed in commonly assigned co-pending U.S. patent application Ser.No. 12/268,064, which is incorporated herein by reference. In someimplementations, a hydrophone for measuring pressure may also be usedwith the three-component MEMS described herein.

The multi-component seismic sensor may be implemented as a single deviceor as a plurality of devices. A particular multi-component seismicsensor may also include pressure gradient sensors, which constituteanother type of particle motion sensors. Each pressure gradient sensormeasures the change in the pressure wavefield at a particular point withrespect to a particular direction. For example, one of the pressuregradient sensors may acquire seismic data indicative of, at a particularpoint, the partial derivative of the pressure wavefield with respect tothe crossline direction, and another one of the pressure gradientsensors may acquire, at a particular point, seismic data indicative ofthe pressure data with respect to the inline direction.

The water vehicle 610 may be deployed to a survey area for seismicsurveying. Where the water vehicle 610 takes the form of an AOV, thewater vehicle 610 may be deployed to a survey area specified on anavigation map, and the water vehicle 610 may automatically makecorrections if the water vehicle 610 veers off-course. Where the watervehicle 610 takes the form of a ROV, the water vehicle 610 may bedeployed to a survey area using remote operation of the water vehicle'srudder.

After deploying the water vehicle 610 to the survey area, a seismicsource 618 may be detonated to generate acoustic waves 620 thatpropagate through an ocean bottom surface 622 and into strata 624, 626beneath the ocean bottom surface. The seismic source 618 may be locatedon another water vehicle 610, as shown in FIG. 6, or more conventionalsource deployments may be used, such as the use of dedicated sourcevessels. The seismic source 618 may be a conventional air gun, marinevibrator, or non-traditional environmentally friendly source. Theseismic source may also include drilling induced acoustic pressurewaves, passive seismic noise, or production induced acoustic pressurewaves, such as those which may result from water or gas injections, orcombinations thereof.

The acoustic signals 620 may be reflected from various subterraneangeological formations, such as formation 628 depicted in FIG. 6. Theincident acoustic signals 620 produce corresponding reflected acousticsignals, or pressure waves 630, which are sensed by the seismic sensors612. In one implementation, the water vehicle 610 may record seismicdata from over one hundred seismic sensors.

The seismic sensors 612 generate signals called “traces,” which indicatethe acquired measurements of the pressure wavefield and particle motionif the sensors include particle motion sensors. The traces are recordedand may be passed to a data acquisition system 632 disposed on the watervehicle 610. The data acquisition system 632 may include a digitizer, acomputer system, and a storage system for storing seismic data acquiredduring the survey. The storage system may include memory, such as in theform of a hard disk drive. In one implementation, the seismic data maybe recorded continuously over days or months at a time. In anotherimplementation, the seismic data may be recorded intermittently, such asafter each detonation of the seismic source 618.

The water vehicle 610 may further include an onboard communication unit634, which may communicate with a base station located onshore or atsea, such as on a rig or vessel. The communication unit 634 may be usedto transmit water vehicle position, quality control parameters, timeinformation, and seismic data. The communication unit 634 may also sendor receive commands particular to the seismic survey. The water vehicle610 may also be powered by batteries, which may be recharged by solarpanels disposed on the top of the water vehicle 610.

Using Augmented Reality Device

As noted above, in conducting a seismic survey, one or more types ofsurvey equipment may be used. For example, in land environments, seismicsources and seismic sensors, such as sources 110 and geophone-receivers118 of FIG. 1.1, may be employed during a seismic survey. Similarly, inmarine environments, survey equipment such as the seismic streamers 505of FIG. 5 and/or water vehicles 610 of FIG. 6 may be employed during aseismic survey. In addition, one or more augmented reality (AR) devicesmay be used to facilitate the placement, recovery, and/or monitoring ofthe survey equipment.

AR Device

An AR device may be a device configured to present an augmented realityto a user. In particular, the augmented reality presented to the usermay be a view of a physical environment, where elements of the physicalenvironment may be supplemented by computer-generated sensory input suchas sound, video, graphics, and/or other data. Types of AR devices mayinclude eyeglass devices, tablet computers, mobile phones, drone cameradevices, helmet devices, goggle devices, and/or any otherimplementations known to those skilled in the art.

In one implementation, one or more AR devices may be used to present aview of a physical environment having at least a portion of a seismicsurvey operation disposed therein to a user. One or more surveyequipment used in the seismic survey may be disposed in this physicalenvironment, and thus may also be displayed in the view. In such animplementation, the view of the physical environment may be supplementedwith information relating to the survey equipment in the form ofcomputer-generated graphics and/or other imagery. In anotherimplementation, the physical environment viewed by the user may belocated proximate to the AR device, such as in front of the AR device.In yet another implementation, the view of the physical environment maybe supplemented with information relating to the physical environmentitself.

Display

The AR device may include a display which may be used to present theview of the physical environment (including the survey equipmentdisposed therein) and the information relating to the survey equipment.In one implementation, the display may be substantially transparent. Insuch an implementation, the user may see a live view of the physicalenvironment by looking through the substantially transparent display. Inaddition, the information relating to the survey equipment may bedisplayed on, in, and/or through the substantially transparent display,such that the information may appear to the user as a graphic and/orimage being superimposed on the view of the live, physical environment.For example, the AR device may be an eyeglass device havingsubstantially transparent lenses, where the lenses are also configuredto display computer-generated graphics and/or imagery to a user, asfurther explained below.

In another implementation, the display of the AR device may be in theform of a monitor. In particular, the monitor may show the view of thephysical environment and the information relating to the surveyequipment, where the view and the information may be generated by the ARdevice. In such an implementation, the view of the physical environmentand the information relating to the survey equipment may be shown on themonitor in real time, near-real time, or delayed time. For example, theview of the physical environment shown on the monitor may be in the formof a video of the physical environment, as taken by a camera coupled tothe AR device. In another example, the view of the physical environmentshown on the monitor may be in the form of a virtual reality simulationof the physical environment. In such an example, the virtual realitysimulation may correspond to the actual physical environment surroundingthe AR device, and the images presented by the simulation may move inconjunction with movement of the AR device. Such an AR device may beused at night, when visibility of the physical environment may be low.

Other Components

As noted above, the AR device may include a camera coupled thereto,where the camera may be used to record video of the physicalenvironment. In one implementation, the camera may be attached directlyto the AR device, such that the camera may record video of the physicalenvironment proximate to the AR device. In another implementation, thecamera may be located remotely from other components of the AR device,and may merely be communicably coupled to said components, including thedisplay. In one such implementation, the camera may record video of aphysical environment located at a distance from other components of theAR device, and may transmit the video to the AR device for display on amonitor of the AR device.

The AR device may also include a computing system, as further describedbelow with respect to FIG. 19. In particular, the computing system mayinclude one or more processing units and one or more forms of computerstorage media, such as a hard disk drive. The AR device may also beconfigured to connect with a network and/or other devices using wiredand/or wireless connections. In one implementation, the AR device maygenerate the view of the physical environment and/or the informationrelating to the survey equipment based on data from its own storagemedia, based on data received via the network and/or other devices, orcombinations thereof.

The AR device may also include a navigation system that may utilize aglobal navigation satellite system (GNSS), such as a global positioningsystem (GPS), to record the position, speed, direction, and otherparameters of the AR device. The GNSS may operate similarly to theglobal positioning system 38 as described above with respect to FIG. 4.In one implementation, the navigation system may include a GPS unitconfigured to interact with the GPS. Though the applications below aredescribed as using GPS, other forms of GNSS may be used instead or inaddition to the GPS.

Examples

Various configurations for an AR device, as known to those skilled inthe art, may be used in connection with a seismic survey, including, butnot limited to, the following implementations.

In one implementation, the AR device may be in the form of wearableelectronics. As noted above, in one such implementation, the AR devicemay take the form of an eyeglass device having substantially transparentlenses, where the lenses may also be configured to displaycomputer-generated graphics and/or imagery to a user. FIG. 7 illustratesan eyeglass device 700 in accordance with implementations of varioustechniques described herein. The eyeglass device 700 may include lenses720, camera 730, computing system (not pictured), and an imaging unit740 disposed on frame 710. In particular, the lenses 720 may besubstantially transparent, such that the user wearing the frame 710 maysee a live view of the physical environment by looking through thelenses 720. The camera 730 may be used to capture data about thephysical environment in front of the user, including the surveyequipment disposed in the environment. The imaging unit 740 may bedisposed on the outside of the lenses 720, and may display informationrelating to survey equipment through the lenses 720, such that theinformation may appear to the user as a graphic and/or image beingsuperimposed on the view of the live, physical environment.

In another implementation, the AR device may include a heads-up display,such as on a windshield of a vehicle. In such an implementation, the ARdevice may include a computing system and an imaging system. While auser may see a live view of the physical environment by looking throughthe windshield, the imaging system may be configured to display theinformation relating to survey equipment on the windshield, such thatthe information may appear to the user as a graphic and/or image beingsuperimposed on the view of the live, physical environment.

In another implementation, the AR device may be a tablet computer havinga camera attached to a back panel of the tablet computer, and where thetablet computer includes a monitor in the form of a touch screen. Insuch an implementation, the touch screen may display the view of thephysical environment, where the view of the physical environment may bein the form of video captured by the camera. The touch screen may alsodisplay information relating to survey equipment, where the informationmay be based on data from the tablet computer's own storage media, basedon data received via a network and/or other devices, or combinationsthereof.

In yet another implementation, the AR device may include a monitorlocated remotely from a camera, as discussed above. In one suchimplementation, the camera may be coupled to a drone device. The dronedevice may be configured to operate in land and/or marine environments.As similarly noted above, the camera coupled to the drone device mayrecord video of a physical environment being traversed by the dronedevice, and may transmit the video to other components of the AR devicefor display on its monitor. The AR device may generate and displayinformation relating to survey equipment based on data from its ownstorage media, based on data received via a network and/or otherdevices, or combinations thereof.

Applications

In conducting a seismic survey, one or more AR devices may be used forvarious applications, including, but not limited to, the followingimplementations.

Sensor Placement

As noted above, in land environments, seismic sensors may be used whenconducting a seismic survey. In one implementation, one or more ARdevices may be used to place the seismic sensors at planned positions ina physical environment to be surveyed. In one implementation, theseismic sensors may be placed in an irregular pattern in the environmentbased on the planned positions. Seismic sensors may include geophonesand/or the like, as discussed above with respect to FIG. 1.1.

FIG. 8 illustrates a flow diagram of a method 800 for placing one ormore seismic sensors in the physical environment using an AR device inaccordance with implementations of various techniques described herein.In one implementation, method 800 may be performed by the AR device. Itshould be understood that while method 800 indicates a particular orderof execution of operations, in some implementations, certain portions ofthe operations might be executed in a different order. Further, in someimplementations, additional operations or blocks may be added to themethod. Likewise, some operations or blocks may be omitted.

At block 810, current location data for the AR device may be determined.The current location data may include a GPS location of the AR device,geographic coordinates of the AR device, and/or the like. The GPSlocation may be determined using the GPS unit of the AR device. In oneimplementation, the AR device may continuously determine its currentlocation data.

In another implementation, the current location data may be transmittedto a central computer using a wired or wireless connection. The centralcomputer may be a computing system positioned at a location away fromthe AR device. In one implementation, the central computer may belocated in the physical environment. In such an implementation, the ARdevice may continuously transmit its current location data to thecentral computer.

At block 820, one or more first placement instructions for a firstseismic sensor may be received. In one implementation, the firstplacement instructions may include navigational instructions forreaching a planned position for the first seismic sensor. The firstplacement instructions may be received from the central computer, whichmay generate the instructions based on the current location datareceived from the AR device. The navigational instructions may includedirections for reaching the planned position efficiently, such as byavoiding hazards. In another implementation, the first placementinstructions may include a GPS location of the planned position,geographic coordinates of the planned position, instructions fororientation of the first seismic sensor, and/or the like.

In one implementation, the AR device may receive updated first placementinstructions based on changes to the current location data sent to thecentral computer. For example, if the AR device were to traverse offcourse, then the first placement instructions may be updated to providenew navigational instructions.

At block 830, the one or more first placement instructions may bedisplayed. In particular, the first placement instructions may bedisplayed on a display of the AR device. In one implementation, the usermay view the physical environment in which the seismic sensors are to beplaced using the display of the AR. The AR device may supplement thisview with the first placement instructions, which may take the form ofcomputer-generated graphics and/or other imagery also displayed by theAR.

For example, the display of the AR device may show turn by turninstructions for reaching the planned position superimposed on the viewof the physical environment. In another example, the display of the ARdevice may show a graphical marker superimposed on the view of thephysical environment, where the graphical marker may represent thelocation of the planned position. In such an example, the size of thegraphical marker displayed to the user may decrease as the AR deviceapproaches the planned position. In yet another implementation, thedisplay of the AR device may show arrows, lines, and/or the like forguidance to the planned position.

Upon placing the first seismic sensor at or near its planned position,the AR device may transmit an updated current location data, receivesecond placement instructions for placing a second seismic sensor at itsplanned position, and subsequently display the second placementinstructions, as similarly described above. The method 800 may berepeated for respective seismic sensors until a sufficient number havebeen placed at their planned positions. In another implementation, uponplacing the seismic sensor at or near the planned position, the GPSlocation of the sensor may be transmitted to the seismic sensor forstorage therein.

In yet another implementation, the AR device itself may generate theplacement instructions for the seismic sensors. In particular, the ARdevice may receive and then store the one or more planned positions forthe seismic sensors, such as from the central computer. The one or moreplanned positions may include GPS coordinates, geographic coordinates,and/or the like for the planned positions. Subsequently, the AR devicemay generate the placement instructions for the sensors based on itscurrent location data and the stored planned positions, and then displaythe placement instructions.

Sensor Retrieval

In one implementation, in land environments, one or more AR devices maybe used to retrieve one or more seismic sensors disposed in a physicalenvironment containing at least a part of a seismic survey. In such animplementation, the seismic sensors may be retrieved due to malfunction,replacement, repairs, routine inspection, and/or the like. In a furtherimplementation, the seismic sensors may be substantially covered or maybe obstructed from view by conditions of the physical environment. Forexample, over time, the seismic sensors may become covered over by sand,snow, vegetation, and/or the like. Seismic sensors may include geophonesand/or the like, as discussed above with respect to FIG. 1.1.

FIG. 9 illustrates a flow diagram of a method 900 for retrieving one ormore seismic sensors in the physical environment using an AR device inaccordance with implementations of various techniques described herein.In one implementation, method 900 may be performed by the AR device. Itshould be understood that while method 900 indicates a particular orderof execution of operations, in some implementations, certain portions ofthe operations might be executed in a different order. Further, in someimplementations, additional operations or blocks may be added to themethod. Likewise, some operations or blocks may be omitted.

At block 910, current location data for the AR device may be determined.The current location data may include a GPS location of the AR device,geographic coordinates of the AR device, and/or the like. The GPSlocation may be determined using the GPS unit of the AR device. In oneimplementation, the AR device may continuously determine its currentlocation data.

At block 920, position data for one or more seismic sensors may bereceived. In one implementation, the position data may include one ormore GPS locations of the seismic sensors, one or more geographiccoordinates of the seismic sensors, and/or the like.

In one implementation, the AR device may receive position data directlyfrom each seismic sensor. In such an implementation, each seismic sensorin the physical environment may continuously broadcast its position datausing a wireless connection, such as via Wi-Fi™ technology, cellulartechnology, Bluetooth™ technology, satellite technology, radio frequency(RF) technology, or any other implementation known to those skilled inthe art. The AR device may detect the broadcasts within a specifiedwireless range of the AR device. In one implementation, the AR devicemay then establish wireless connections with one or more of the detectedsensors based on certain criteria. Such criteria may include thosedetected seismic sensors being within the view of the physicalenvironment displayed by the AR device and/or having the strongestwireless connection. Upon establishing the wireless connections with oneor more of the detected sensors, the AR device may then receive theposition data for the one or more of the detected sensors.

In another implementation, the AR device may receive the position datafor one or more seismic sensors from the central computer. In yetanother implementation, the AR device may retrieve the position data forone or more seismic sensors from the storage media of the AR device.

At block 930, one or more retrieval data for the one or more seismicsensors may be generated. The retrieval data may include distances toeach of the seismic sensors, navigational instructions to each of theseismic sensors, and/or the like. The retrieval data may be generatedbased on the position data of the seismic sensors and the currentlocation data for the AR device.

At block 940, the one or more retrieval data may be displayed. Inparticular, the retrieval data may be displayed on the display of the ARdevice. In one implementation, the user may view the physicalenvironment containing the one or more seismic sensors using the displayof the AR. The AR device may supplement this view with the retrievaldata, which may take the form of computer-generated graphics and/orother imagery also displayed by the AR. Such displayed retrieval datamay assist a user with retrieving the seismic sensors from the physicalenvironment.

For example, the display of the AR device may show turn by turninstructions for reaching a seismic sensor superimposed on the view ofthe physical environment. In another example, the display of the ARdevice may show one or more graphical markers superimposed on the viewof the physical environment, where the graphical markers may representthe locations of the one or more seismic sensors.

FIG. 10 illustrates a schematic of a display 1000 of an AR device inaccordance with implementations of various techniques described herein.Display 1000 of the AR device shows a view of a physical environment1010 supplemented with various retrieval data 1020. Such retrieval data1020 may include sensor identification numbers, distance numbers fromthe AR device, directional arrows to other seismic sensors, and/or thelike.

In one implementation, the method 900 may be repeated for remainingseismic sensors until a sufficient number have been retrieved. Inanother implementation, the method 900 may be similarly used to retrieveseismic sources disposed in the physical environment.

Sensor Status

In one implementation, in land environments, the AR device may be usedto determine status data of one or more seismic sensors disposed in aphysical environment containing at least a part of a seismic survey. Insuch an implementation, the status data of the one or more sensors mayinclude diagnostics, health status, repairs needed, power status, dataon repairs and/or maintenance to be performed, repair and/or maintenanceinstructions, distress codes, orientation data, and/or the like. Seismicsensors may include geophones and/or the like, as discussed above withrespect to FIG. 1.1.

FIG. 11 illustrates a flow diagram of a method 1100 for obtaining statusdata for one or more seismic sensors in the physical environment usingan AR device in accordance with implementations of various techniquesdescribed herein. In one implementation, method 1100 may be performed bythe AR device. It should be understood that while method 1100 indicatesa particular order of execution of operations, in some implementations,certain portions of the operations might be executed in a differentorder. Further, in some implementations, additional operations or blocksmay be added to the method. Likewise, some operations or blocks may beomitted.

At block 1110, the AR device may display a view of the physicalenvironment having one or more seismic sensors disposed therein. In oneimplementation, the AR device may supplement this view with theretrieval data for each of the seismic sensors, as discussed above withrespect to FIG. 9.

At block 1120, the AR device may receive status data for the one or moreseismic sensors. In one implementation, each seismic sensor maycontinuously broadcast its status data using a wireless connection, suchas via Wi-Fi™ technology, cellular technology, Bluetooth™ technology,satellite technology, (RF) technology, or any other implementation knownto those skilled in the art. The AR device may detect the broadcastswithin a specified wireless range of the AR device. In oneimplementation, the AR device may then establish a wireless connectionwith one or more particular seismic sensors of the detected sensorsbased on certain criteria. Such criteria may include the seismic sensorbeing within the view of the physical environment displayed by the ARdevice. Upon establishing the wireless connection, the AR device mayreceive the status data from each wirelessly connected seismic sensor.In yet another implementation, the AR device may receive the status datafrom the central computer.

At block 1130, the AR device may display the received status data. Inone implementation, the AR device may supplement the view of thephysical environment with the received status data, which may take theform of computer-generated graphics and/or other imagery also displayedby the AR. In one implementation, the received status data could be usedfor troubleshooting the one or more seismic sensors disposed in thephysical environment.

FIG. 12 illustrates a schematic of a display 1200 of an AR device inaccordance with implementations of various techniques described herein.Display 1200 of the AR device shows a view of a physical environment1210 supplemented with various status data 1220 for a particular seismicsensor. Such status data 1220 may include battery power data,orientation data, and/or the like.

Seismic Truck Placement

In one implementation, in land environments, survey equipment such asone or more seismic trucks may be used when conducting a seismic survey.In particular, the seismic trucks may contain one or more seismicsources, such as vibrators. The seismic sources may produce soundvibrations, similar to the sources 110 of FIG. 1.1. In such animplementation, each seismic truck may operate at one or more plannedpositions in a physical environment to be surveyed. Accordingly, one ormore AR devices may be used to place each seismic truck at its plannedpositions.

FIG. 13 illustrates a flow diagram of a method 1300 for placing aseismic truck in one or more planned positions in the physicalenvironment using an AR device in accordance with implementations ofvarious techniques described herein. In one implementation, method 1300may be performed by the AR device. It should be understood that whilemethod 1300 indicates a particular order of execution of operations, insome implementations, certain portions of the operations might beexecuted in a different order. Further, in some implementations,additional operations or blocks may be added to the method. Likewise,some operations or blocks may be omitted. In particular, the AR devicemay include a heads-up display, such as a windshield of the seismictruck, as similarly discussed above. Further, the AR device may bedisposed on board the seismic truck.

At block 1310, current location data for the AR device may bedetermined. The current location data may include a GPS location of theAR device, geographic coordinates of the AR device, and/or the like. TheGPS location may be determined using the GPS unit of the AR device. Inone implementation, the AR device may continuously determine its currentlocation data.

In another implementation, the current location data may be transmittedto a central computer using a wired or wireless connection. In such animplementation, the AR device may continuously transmit its currentlocation data to the central computer.

At block 1320, one or more first placement instructions for the seismictruck may be received. In one implementation, the first placementinstructions may include navigational instructions for reaching a firstplanned position for the seismic truck. The first placement instructionsmay be received from the central computer, which may generate theinstructions based on the current location data received from the ARdevice. The navigational instructions may include directions forreaching the first planned position efficiently, such as by avoidinghazards.

In another implementation, the first placement instructions may includea GPS location of the first planned position, geographic coordinates ofthe first planned position, and/or the like. In another implementation,the AR device may receive updated first placement instructions based onchanges to the current location data sent to the central computer. Forexample, if the AR device were to traverse off course, then the firstplacement instructions may be updated to provide new navigationalinstructions.

At block 1330, the one or more first placement instructions may bedisplayed. In particular, the first placement instructions may bedisplayed on a display of the AR device. In one implementation, the usermay view the physical environment in which the seismic sensors are to beplaced using the display of the AR. The AR device may supplement thisview with the first placement instructions, which may take the form ofcomputer-generated graphics and/or other imagery also displayed by theAR.

For example, the display of the AR device may show turn by turninstructions for reaching the planned position superimposed on the viewof the physical environment. In another example, the display of the ARdevice may show a graphical marker superimposed on the view of thephysical environment, where the graphical marker may represent thelocation of the planned position.

Upon placing the seismic truck at or near its first planned position,one or more seismic sources in the seismic truck may be activated. Uponcompletion of the activation, the AR device may transmit an updatedcurrent location data, receive second placement instructions for placingthe truck at its second planned position, and subsequently display thesecond placement instructions, as similarly described above. The method1300 may be repeated for respective planned positions until a sufficientnumber have been reached by the truck.

Seismic Streamer Status

In one implementation, in marine environments, survey equipment such asone or more seismic streamers may be used when conducting a seismicsurvey, as described above with respect to FIG. 5. In particular, asurvey vessel may tow one or more seismic streamers behind the vessel.In towing the streamers, conditions of the streamers, vessel, and watermay lead to tangling and disorientation of the streamer shape.Accordingly, one or more AR devices may be used to determine a status ofthe one or more seismic streamers disposed in a physical environmenthaving at least a part of a seismic survey operation.

FIG. 14 illustrates a flow diagram of a method 1300 for obtaining statusdata for one or more seismic streamers in the physical environment usingan AR device in accordance with implementations of various techniquesdescribed herein. In one implementation, method 1400 may be performed bythe AR device. It should be understood that while method 1400 indicatesa particular order of execution of operations, in some implementations,certain portions of the operations might be executed in a differentorder. Further, in some implementations, additional operations or blocksmay be added to the method. Likewise, some operations or blocks may beomitted.

At block 1410, the AR device may display a view of the physicalenvironment having one or more seismic streamers disposed therein. Inparticular, the AR device may be positioned to display a rear of thevessel towing the seismic streamers.

At block 1420, the AR device may receive status data for the one or moreseismic streamers. The status data may include the estimated positionsof the streamers in the water. In particular, the status data mayinclude data on the depth, separation, placement, and/or the like of theseismic streamers. The status data may be received from a centralcomputer disposed on board the vessel.

In particular, the central computer may generate the status data basedon estimated values for position, lift, drag, and/or the like of theseismic streamers. In one implementation, these estimated values may bederived using the acoustic position system as described with respect toFIG. 5. In particular, acoustic positioning sources and receivers may beused to calculate the relative positions of the acoustic positioningsources and/or the acoustic positioning receivers in the seismicstreamers. In turn, these calculated positions may be used to develop apositioning model to enable estimation of positioning of the seismicstreamers, including location, depth, and/or the like.

At block 1430, the AR device may display the received status data. Inone implementation, the AR device may supplement the view of thephysical environment with the received status data, which may take theform of computer-generated graphics and/or other imagery also displayedby the AR. In one implementation, the received status data could be usedfor troubleshooting the one or more seismic sensors disposed in thephysical environment.

FIG. 15 illustrates a system diagram for determining a status of the oneor more seismic streamers disposed in a physical environment inaccordance with implementations of various techniques described herein.As shown, the seismic streamers 1510 and its acoustic positioning system1520 may be in communication with a central computer 1530 disposedaboard a vessel. The central computer may generate the status data forthe seismic streamers 1410 and may transmit the status data to the ARdevice 1540. In turn, a display 1550 of the AR device 1540 may present aview of the physical environment to a user along with the supplementedstatus data.

FIG. 16 illustrates a schematic diagram of a display 1600 of an ARdevice in accordance with implementations of various techniquesdescribed herein. Display 1600 of the AR device shows a view of aphysical environment 1610 supplemented with various status data 1620 forone or more seismic streamers 1630. As shown, the status data 1620 mayinclude data relating to depth of the streamers, separation between thestreamers, and/or streamer shape.

Seismic Node Status

In another implementation, one or more AR devices may be similarly usedto determine a status of the one or more seismic nodes disposed in aphysical environment having at least a part of a seismic surveyoperation. In one implementation, a seismic node may include seismicsensors freely disposed on the surface of the water and/or along a seabottom.

In such an implementation, the AR device aboard the vessel may receivestatus data for the one or more seismic streamers. The status data mayinclude the estimated positions of the streamers in the water. Inparticular, the status data may include data on the depth, separation,placement, and/or the like of the seismic streamers. The status data maybe received from a central computer disposed on board the vessel. Assimilarly discussed above with respect to FIG. 13, the AR device maydisplay the received status data. In one implementation, the AR devicemay supplement the view of the physical environment with the receivedstatus data, which may take the form of computer-generated graphicsand/or other imagery also displayed by the AR.

FIG. 17 illustrates a schematic diagram of a display 1700 of an ARdevice in accordance with implementations of various techniquesdescribed herein. Display 1700 of the AR device shows a view of aphysical environment 1710 supplemented with various status data 1720 forone or more seismic nodes 1730. As shown, the status data may includedata relating to identification, distance, bearing, speed, and/or thelike for the seismic nodes 1730.

Water Vehicles

In one implementation, in marine environments, survey equipment such asone or more water vehicles may be used when conducting a seismic survey,as described above with respect to FIG. 6. In particular, the watervehicles may be used for seismic surveying and may include one or moresensors.

As similarly described above with respect to seismic sensors in landenvironments, one or more AR devices may be used to place the watervehicles at planned positions in a physical environment to be surveyed,to retrieve the one or more water vehicles disposed in the physicalenvironment, and/or determine a status of the one or more water vehiclesdisposed in the physical environment.

FIG. 18 illustrates a system diagram for using an AR device with one ormore water vehicles 1810 disposed in a physical environment inaccordance with implementations of various techniques described herein.With respect to retrieving and/or displaying status data for the watervehicles 1810, the water vehicles 1810 may communicate its positionand/or status data with a central computer on board a rig or vessel 1820via satellite communication 1830. In turn, the central computer maygenerate retrieval instructions and/or communicate the status data to anAR device disposed on the rig or vessel for display.

Computing Systems

Implementations of various technologies described herein may beoperational with numerous general purpose or special purpose computingsystem environments or configurations. Examples of well known computingsystems, environments, and/or configurations that may be suitable foruse with the various technologies described herein include, but are notlimited to, personal computers, server computers, hand-held or laptopdevices, multiprocessor systems, microprocessor-based systems, set topboxes, programmable consumer electronics, network PCs, minicomputers,mainframe computers, smartphones, smartwatches, personal wearablecomputing systems networked with other computing systems, tabletcomputers, and distributed computing environments that include any ofthe above systems or devices, and the like.

The various technologies described herein may be implemented in thegeneral context of computer-executable instructions, such as programmodules, being executed by a computer. Generally, program modulesinclude routines, programs, objects, components, data structures, etc.that performs particular tasks or implement particular abstract datatypes. While program modules may execute on a single computing system,it should be appreciated that, in some implementations, program modulesmay be implemented on separate computing systems or devices adapted tocommunicate with one another. A program module may also be somecombination of hardware and software where particular tasks performed bythe program module may be done either through hardware, software, orboth.

The various technologies described herein may also be implemented indistributed computing environments where tasks are performed by remoteprocessing devices that are linked through a communications network,e.g., by hardwired links, wireless links, or combinations thereof. Thedistributed computing environments may span multiple continents andmultiple vessels, ships or boats. In a distributed computingenvironment, program modules may be located in both local and remotecomputer storage media including memory storage devices.

FIG. 19 illustrates a schematic diagram of a computing system 1900 inwhich the various technologies described herein may be incorporated andpracticed. Although the computing system 1900 may be a conventionaldesktop or a server computer, as described above, other computer systemconfigurations may be used.

The computing system 1900 may include a central processing unit (CPU)1930, a system memory 1926, a graphics processing unit (GPU) 1931 and asystem bus 1928 that couples various system components including thesystem memory 1926 to the CPU 1930. Although one CPU is illustrated inFIG. 19, it should be understood that in some implementations thecomputing system 1900 may include more than one CPU. The GPU 1931 may bea microprocessor specifically designed to manipulate and implementcomputer graphics. The CPU 1930 may offload work to the GPU 1931. TheGPU 1931 may have its own graphics memory, and/or may have access to aportion of the system memory 1926. As with the CPU 1930, the GPU 1931may include one or more processing units, and the processing units mayinclude one or more cores. The system bus 1928 may be any of severaltypes of bus structures, including a memory bus or memory controller, aperipheral bus, and a local bus using any of a variety of busarchitectures. By way of example, and not limitation, such architecturesinclude Industry Standard Architecture (ISA) bus, Micro ChannelArchitecture (MCA) bus, Enhanced ISA (EISA) bus, Video ElectronicsStandards Association (VESA) local bus, and Peripheral ComponentInterconnect (PCI) bus also known as Mezzanine bus. The system memory1926 may include a read-only memory (ROM) 1912 and a random accessmemory (RAM) 1946. A basic input/output system (BIOS) 1914, containingthe basic routines that help transfer information between elementswithin the computing system 1900, such as during start-up, may be storedin the ROM 1912.

The computing system 1900 may further include a hard disk drive 1950 forreading from and writing to a hard disk, a magnetic disk drive 1952 forreading from and writing to a removable magnetic disk 1956, and anoptical disk drive 1954 for reading from and writing to a removableoptical disk 1958, such as a CD ROM or other optical media. The harddisk drive 1950, the magnetic disk drive 1952, and the optical diskdrive 1954 may be connected to the system bus 1928 by a hard disk driveinterface 1936, a magnetic disk drive interface 1938, and an opticaldrive interface 1940, respectively. The drives and their associatedcomputer-readable media may provide nonvolatile storage ofcomputer-readable instructions, data structures, program modules andother data for the computing system 1900.

Although the computing system 1900 is described herein as having a harddisk, a removable magnetic disk 1956 and a removable optical disk 1958,it should be appreciated by those skilled in the art that the computingsystem 1900 may also include other types of computer-readable media thatmay be accessed by a computer. For example, such computer-readable mediamay include computer storage media and communication media. Computerstorage media may include volatile and non-volatile, and removable andnon-removable media implemented in any method or technology for storageof information, such as computer-readable instructions, data structures,program modules or other data. Computer storage media may furtherinclude RAM, ROM, erasable programmable read-only memory (EPROM),electrically erasable programmable read-only memory (EEPROM), flashmemory or other solid state memory technology, CD-ROM, digital versatiledisks (DVD), or other optical storage, magnetic cassettes, magnetictape, magnetic disk storage or other magnetic storage devices, or anyother medium which can be used to store the desired information andwhich can be accessed by the computing system 1900. Communication mediamay embody computer readable instructions, data structures, programmodules or other data in a modulated data signal, such as a carrier waveor other transport mechanism and may include any information deliverymedia. The term “modulated data signal” may mean a signal that has oneor more of its characteristics set or changed in such a manner as toencode information in the signal. By way of example, and not limitation,communication media may include wired media such as a wired network ordirect-wired connection, and wireless media such as acoustic, RF,infrared and other wireless media. The computing system 1900 may alsoinclude a host adapter 1933 that connects to a storage device 1935 via asmall computer system interface (SCSI) bus, a Fiber Channel bus, aneSATA bus, or using any other applicable computer bus interface.Combinations of any of the above may also be included within the scopeof computer readable media.

A number of program modules may be stored on the hard disk 1950,magnetic disk 1956, optical disk 1958, ROM 1912 or RAM 1916, includingan operating system 1918, one or more application programs 1920, programdata 1924, and a database system 1948. The application programs 1920 mayinclude various mobile applications (“apps”) and other applicationsconfigured to perform various methods and techniques described herein.The operating system 1918 may be any suitable operating system that maycontrol the operation of a networked personal or server computer, suchas Windows® XP, Mac OS® X, Unix-variants (e.g., Linux® and BSD®), andthe like.

A user may enter commands and information into the computing system 1900through input devices such as a keyboard 1962 and pointing device 1960.Other input devices may include a microphone, joystick, game pad,satellite dish, scanner, or the like. These and other input devices maybe connected to the CPU 1930 through a serial port interface 1942coupled to system bus 1928, but may be connected by other interfaces,such as a parallel port, game port or a universal serial bus (USB). Amonitor 1934 or other type of display device may also be connected tosystem bus 1928 via an interface, such as a video adapter 1932. Inaddition to the monitor 1934, the computing system 1900 may furtherinclude other peripheral output devices such as speakers and printers.

Further, the computing system 1900 may operate in a networkedenvironment using logical connections to one or more remote computers1974. The logical connections may be any connection that is commonplacein offices, enterprise-wide computer networks, intranets, and theInternet, such as local area network (LAN) 1976 and a wide area network(WAN) 1966. The remote computers 1974 may be another a computer, aserver computer, a router, a network PC, a peer device or other commonnetwork node, and may include many of the elements describes aboverelative to the computing system 1900. The remote computers 1974 mayalso each include application programs 1970 similar to that of thecomputer action function.

When using a LAN networking environment, the computing system 1900 maybe connected to the local network 1976 through a network interface oradapter 1944. When used in a WAN networking environment, the computingsystem 1900 may include a router 1964, wireless router or other meansfor establishing communication over a wide area network 1966, such asthe Internet. The router 1964, which may be internal or external, may beconnected to the system bus 1928 via the serial port interface 1942. Ina networked environment, program modules depicted relative to thecomputing system 1900, or portions thereof, may be stored in a remotememory storage device 1972. It will be appreciated that the networkconnections shown are merely examples and other means of establishing acommunications link between the computers may be used.

The network interface 1944 may also utilize remote access technologies(e.g., Remote Access Service (RAS), Virtual Private Networking (VPN),Secure Socket Layer (SSL), Layer 2 Tunneling (L2T), or any othersuitable protocol). These remote access technologies may be implementedin connection with the remote computers 1974.

It should be understood that the various technologies described hereinmay be implemented in connection with hardware, software or acombination of both. Thus, various technologies, or certain aspects orportions thereof, may take the form of program code (i.e., instructions)embodied in tangible media, such as floppy diskettes, CD-ROMs, harddrives, or any other machine-readable storage medium wherein, when theprogram code is loaded into and executed by a machine, such as acomputer, the machine becomes an apparatus for practicing the varioustechnologies. In the case of program code execution on programmablecomputers, the computing device may include a processor, a storagemedium readable by the processor (including volatile and non-volatilememory and/or storage elements), at least one input device, and at leastone output device. One or more programs that may implement or utilizethe various technologies described herein may use an applicationprogramming interface (API), reusable controls, and the like. Suchprograms may be implemented in a high level procedural or objectoriented programming language to communicate with a computer system.However, the program(s) may be implemented in assembly or machinelanguage, if desired. In any case, the language may be a compiled orinterpreted language, and combined with hardware implementations. Also,the program code may execute entirely on a user's computing device, onthe user's computing device, as a stand-alone software package, on theuser's computer and on a remote computer or entirely on the remotecomputer or a server computer.

The computing system 1900 may be located at a data center remote fromthe survey region. The computing system 1900 may be in communicationwith the receivers (either directly or via a recording unit, not shown),to receive signals indicative of the reflected seismic energy. Thesesignals, after conventional formatting and other initial processing, maybe stored by the computing system 1900 as digital data in the diskstorage for subsequent retrieval and processing in the manner describedabove. In one implementation, these signals and data may be sent to thecomputing system 1900 directly from sensors, such as geophones,hydrophones and the like. When receiving data directly from the sensors,the computing system 1900 may be described as part of an in-field dataprocessing system. In another implementation, the computing system 1900may process seismic data already stored in the disk storage. Whenprocessing data stored in the disk storage, the computing system 1900may be described as part of a remote data processing center, separatefrom data acquisition. The computing system 1900 may be configured toprocess data as part of the in-field data processing system, the remotedata processing system or a combination thereof.

Those with skill in the art will appreciate that any of the listedarchitectures, features or standards discussed above with respect to theexample computing system 1900 may be omitted for use with a computingsystem used in accordance with the various embodiments disclosed hereinbecause technology and standards continue to evolve over time.

Of course, many processing techniques for collected data, including oneor more of the techniques and methods disclosed herein, may also be usedsuccessfully with collected data types other than seismic data. Whilecertain implementations have been disclosed in the context of seismicdata collection and processing, those with skill in the art willrecognize that one or more of the methods, techniques, and computingsystems disclosed herein can be applied in many fields and contextswhere data involving structures arrayed in a three-dimensional spaceand/or subsurface region of interest may be collected and processed,e.g., medical imaging techniques such as tomography, ultrasound, MRI andthe like for human tissue; radar, sonar, and LIDAR imaging techniques;and other appropriate three-dimensional imaging problems.

The foregoing description, for purpose of explanation, has beendescribed with reference to specific implementations. However, theillustrative discussions above are not intended to be exhaustive or tolimit the above-described implementations to the precise formsdisclosed. Many modifications and variations are possible in view of theabove teachings. The implementations were chosen and described in orderto explain the principles of the above-described implementations andtheir practical applications, to thereby enable others skilled in theart to utilize the above-described implementations with variousmodifications as are suited to the particular use contemplated.

What is claimed is:
 1. A method, comprising: displaying a view of aphysical environment on an augmented reality (AR) device, wherein thephysical environment comprises one or more seismic survey equipmentdisposed therein; receiving status data at the augmented reality (AR)device for the one or more seismic survey equipment; displaying thestatus data in combination with a view of the physical environment; andwherein the status data comprises at least one selected from a listconsisting of: diagnostics data, health status data, power status, dataon repairs and/or maintenance to be performed, data on repair and/ormaintenance instructions, distress codes, orientation data, orcombinations thereof.
 2. The method of claim 1, wherein receiving thestatus data comprises receiving the status data directly from the one ormore seismic survey equipment using a wireless connection, from acentral computer, or combinations thereof.
 3. The method of claim 1,wherein displaying the status data comprises superimposing the statusdata on the view of the physical environment, and wherein the statusdata comprises computer-generated graphics.
 4. The method of claim 1,wherein the AR device is configured to wirelessly communicate with theseismic survey equipment appearing in the view of the physicalenvironment displayed by the AR device.
 5. The method of claim 1,wherein the seismic survey equipment comprises one or more seismicsensors, one or more seismic streamers, one or more water vehicles, oneor more seismic nodes, or combinations thereof.
 6. A method, comprising:displaying a view of a physical environment on an augmented reality (AR)device, wherein the physical environment comprises one or more seismicsurvey equipment disposed therein; receiving status data at theaugmented reality (AR) device for the one or more seismic surveyequipment; displaying the status data in combination with a view of thephysical environment; and wherein the status data is data relating tothe inner mechanical workings of the seismic survey equipment.
 7. Themethod of claim 6, wherein receiving the status data comprises receivingthe status data directly from the one or more seismic survey equipmentusing a wireless connection, from a central computer, or combinationsthereof.
 8. The method of claim 6, wherein displaying the status datacomprises superimposing the status data on the view of the physicalenvironment, and wherein the status data comprises computer-generatedgraphics.
 9. The method of claim 6, wherein the AR device is configuredto wirelessly communicate with the seismic survey equipment appearing inthe view of the physical environment displayed by the AR device.
 10. Themethod of claim 6, wherein the seismic survey equipment comprises one ormore seismic sensors, one or more seismic streamers, one or more watervehicles, one or more seismic nodes, or combinations thereof.